Fuel compositions comprising natural gas and synthetic hydrocarbons and methods for preparation of same

ABSTRACT

The invention is directed to compositions comprising mixtures of natural gas and synthetic light hydrocarbons, such as C 2  to C 5  paraffins, olefins and mixtures thereof, obtained via a hydrocarbon synthesis reactions, which are suitable for use as fuel compositions, and particularly to blends of such synthetic light hydrocarbons and a natural gas derived from LNG produced in an LNG process. Alternatively, such blends may also be obtained by liquefaction of the synthetic light hydrocarbons with natural gas in an LNG process. The synthetic light hydrocarbons are added, for example, to a lean natural gas to improve the heat value thereof. In embodiments, the synthetic light hydrocarbons are conveniently derived, at least in part, from low value CO 2  contaminant that may be present in a raw natural gas stream used to prepare LNG. Also disclosed are methods to prepare the mixtures.

CROSS REFERENCE TO RELATED APPLICATION

This application claims benefit and is a continuation-in-part ofco-pending U.S. patent application Ser. No. 10/805,943, filed Mar. 22,2004, the teachings of which are incorporated herein by reference intheir entirety.

FIELD OF THE INVENTION

The present invention relates to fuel compositions derived from naturalgas, and in particular to fuel gas compositions comprising blends ofsynthetic light hydrocarbons and natural gas, including natural gascomponents derived from liquefied natural gas (LNG), and also methodsfor preparation of the fuel blends.

BACKGROUND OF THE INVENTION

Natural gas generally refers to rarefied or gaseous hydrocarbons(comprised of methane and light hydrocarbons such as ethane, propane,butane, and the like) which are found in the earth. Non-combustiblegases occurring in the earth, such as carbon dioxide, helium andnitrogen are generally referred to by their proper chemical names.Often, however, non-combustible gases are found in combination withcombustible gases and the mixture is referred to generally as “naturalgas” without any attempt to distinguish between combustible andnon-combustible gases. See Pruitt, “Mineral Terms—Some Problems in TheirUse and Definition,” Rocky Mt. Min. L. Rev. 1, 16 (1966).

Natural gas is often plentiful in regions where it is uneconomical todevelop those reserves due to lack of a local market for the gas or thehigh cost of processing and transporting the gas to distant markets.Such natural gas is accordingly referred to in the energy industry as“stranded gas” or “remote gas”. Recently a number of methods have beeninvestigated and/or proposed to allow for more economic use of suchresources by converting the stranded gas into liquid products which aremore readily transportable, such as methanol, dimethyl ether or otherchemicals, as well as liquid hydrocarbons via Fischer-Tropschhydrocarbon synthesis.

It is also commercially important to cryogenically liquefy natural gasso as to produce LNG for more convenient storage and transport. Afundamental reason for the liquefaction of natural gas is thatliquefaction results in a volume reduction of about 1/600, therebymaking it possible to store and transport the liquefied gas incontainers at low or even atmospheric pressure. Liquefaction of naturalgas is of even greater importance in enabling the transport of gas froma supply source to market where the source and market are separated bygreat distances and pipeline transport is not practical or economicallyfeasible.

In order to store and transport natural gas in the liquid state, thenatural gas is preferably cooled to −240° F. (−151° C.) to −260° F.(−162° C.) where it may exist as a liquid at near atmospheric vaporpressure. Various methods and/or systems exist in the prior art forliquefying natural gas or the like whereby the gas is liquefied bysequentially passing the gas at an elevated pressure through a pluralityof cooling stages, and cooling the gas to successively lowertemperatures until liquefaction is achieved. Cooling is generallyaccomplished by heat exchange with one or more refrigerants such aspropane, propylene, ethane, ethylene, nitrogen and methane, or mixturesthereof. The refrigerants are commonly arranged in a cascaded manner, inorder of diminishing refrigerant boiling point. For example, processesfor preparation of LNG generally are disclosed in U.S. Pat. Nos.4,445,917; 5,537,827; 6,023,942; 6,041,619; 6,062,041; 6,248,794, and UKPatent Application GB 2,357,140 A. The teachings of these patents areincorporated herein by reference in their entirety.

Natural gas produced from some subterranean reservoirs can comprise avery lean gas, i.e., a gas wherein the hydrocarbon content ispredominately methane with only relatively minor levels (less than about3 mol %) of higher molecular weight natural, i.e., virgin, hydrocarbonstherein, such as those hydrocarbons boiling greater than methane,typically C₂-C₅ hydrocarbons. Further, the natural gas industry,including those who produce LNG, may remove at least a portion of thehigher molecular weight hydrocarbons present in the natural gasdepending on the local market demands, and direct them to other uses. Asa result, when such lean natural gas is used as a feed to produce LNG,the resulting LNG can have an undesirably low heating value, such asless than 1000 BTU/SCF. Consumers of LNG can typically require a higherheating value, such as from about 1000 BTU/SCF to about 1200 BTU/SCF andeven higher.

Historically, to meet the market demand in some markets where increasedLNG heating value is desired, the LNG product heating value has beenincreased by blending it with selected amounts of light virginhydrocarbons, such as ethane, propane, or butanes, which are most oftensupplied as a mixture typically referred to as liquefied petroleum gasor “LPG”. The amount of LPG blended therein is that sufficient to meetthe market specification. This practice may not always be economical forthe LNG producer and/or LNG consumer. For example, if the natural gas isvery lean or a source of LPG is not readily available at the site wherethe natural gas is converted to LNG or where the LNG is re-gasified foruse by a consumer thereof, then LPG must be shipped to such sites. Atpresent, a significant quantity of LNG is consumed in the Asian Pacificmarkets and to meet heating value specifications in this market for someLNG products, LPG is shipped long distances for blending with low heatvalue LNG products. As a result, this practice increases the costsassociated with such LNG products.

As can be seen, it would be desirable to develop alternatives so as toimprove the heat value of natural gas and in particular, to utilize leannatural gas sources and increase the heat value of LNG producedtherefrom without relying on expensive transport of LPG materials. Suchalternatives could make such natural gas supplies a more economical andcommercially attractive energy resource from the perspective of both LNGproducers and consumers.

SUMMARY OF THE INVENTION

The foregoing objectives may be attained by the present invention, whichin one aspect relates to a composition comprising a natural gascomponent and a synthetic hydrocarbon component comprised of lightsynthetic hydrocarbons. The composition may comprise a blend of thenatural gas component and the synthetic hydrocarbon component in liquidform, such as that obtained by condensing both the natural gas componentand synthetic hydrocarbon component in a LNG process; or in vapor form,such as that obtained by mixing a regasified LNG product with thesynthetic hydrocarbon component in the vapor phase, or by mixing aproduced natural gas with the synthetic hydrocarbon component in thevapor phase.

In another aspect, the invention relates to a method for preparing afuel blend comprising mixing a natural gas component with a synthetichydrocarbon component comprised of light synthetic hydrocarbons.

In embodiments, the method further comprises preparing the natural gascomponent by the steps of:

-   -   pre-treating a natural gas stream comprising acid gases, water        and other contaminants therein to remove at least a portion of        the contaminants therefrom and provide a natural gas feed;    -   cooling the natural gas feed in a LNG process to liquefy at        least a portion of the natural gas feed and thereby produce a        LNG product; and    -   re-gasifying the LNG product to obtain the natural gas        component. In further embodiments of the foregoing, the method        also comprises adding the following steps of:    -   providing the synthetic hydrocarbon component; and    -   mixing the synthetic hydrocarbon component with the natural gas        component in the vapor phase to obtain the fuel blend.

Where the synthetic hydrocarbon component and natural gas component aremixed in the vapor phase, the synthetic hydrocarbon component may beadded in any amount to achieve a desired higher heating value, provided,however, that the resulting fuel blend will be maintained below thehydrocarbon dew point for the pressure and temperatures at which thefuel blend is to be stored or conveyed, typically those conditions beingspecified for the pipeline in which the fuel blend is to be conveyed tomarket or the ultimate user thereof. Typically, the amount of synthetichydrocarbon added will be less than 25 mol % based on the total fuelblend, including from 1 to 25 mol %, and beneficially from 10-15 mol %of the total fuel blend.

In the above-described embodiments of the method, it may be convenientto re-gasify the LNG product and mix it with the synthetic hydrocarboncomponent at a site remote from a location where the natural gas feedoriginates, and more particularly, at a location near the market for thefuel blend.

In other embodiments where the synthetic hydrocarbon is mixed with anatural gas component in a LNG process, the method further comprises:

-   -   pre-treating a natural gas stream comprising acid gases, water        and other contaminants therein to remove at least a portion of        the contaminants therefrom and provide a natural gas feed for        the LNG process;    -   mixing the synthetic hydrocarbon component into the natural gas        feed of the LNG process at a temperature and in an amount such        that the synthetic hydrocarbon component does not solidify and        form a separate solid phase during liquefaction of the natural        gas feed in the LNG process;    -   cooling the resulting natural gas and synthetic hydrocarbon        mixture within the LNG process to a temperature of from about        −240° F. (−151° C.) to about −260° F. (−162° C.) or less so as        to liquefy at least a portion of the mixture and thereby produce        a blended liquid product at substantially atmospheric pressure;        and    -   re-gasifying the blended liquid product to produce the fuel        blend.

Where the synthetic hydrocarbon component is mixed with the natural gasfeed in a LNG process, the mixing may be in the vapor phase, the liquidphase, or both, and the synthetic hydrocarbon may be added in an amountto achieve a desired higher heating value when the blended liquidproduct is regasified, provided, that the amount of synthetichydrocarbon added will not result in solidification of the synthetichydrocarbon in the blended liquid product, typically 25 mol % or lessbased on the total blended liquid product.

The blended liquid product according to the foregoing method can beconveniently re-gasified just prior to use to produce the desired fuelblend, and in particular, at a site remote from a location where thenatural gas stream originates or the blended liquid product is produced,such as a location near the market for the fuel blend.

In another aspect, the invention is directed to a method for preparing afuel blend comprising natural gas and a synthetic hydrocarbon component.The method comprises:

-   -   pre-treating a natural gas stream comprising acid gases, water        and other contaminants therein to remove at least a portion of        the contaminants therefrom and provide a natural gas feed;    -   cooling the natural gas feed in a LNG process to liquefy at        least a portion of the natural gas feed and thereby produce a        LNG product;    -   providing the synthetic hydrocarbon component;    -   re-gasifying the LNG product to obtain the natural gas        component; and    -   mixing the synthetic hydrocarbon component with the natural gas        component in the vapor phase to obtain the fuel blend.        In the above-described embodiment, it may be convenient to        re-gasify the LNG product and mix it with the synthetic        hydrocarbon component at a site remote from a location where the        natural gas feed originates or the LNG product is produced, and        more particularly, at a location near the market for the fuel        blend.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic process flow sheet illustrating a process forpreparing methanol with a feed that includes all or a portion of CO₂contaminant that may be separated and recovered from a lean natural gasproduced from a subterranean reservoir. At least a portion of themethanol may then be reacted to form light olefins or paraffins(synthetic hydrocarbons) in a hydrocarbon synthesis process, whichsynthetic hydrocarbons in turn can then be mixed with the natural gas toform a fuel blend composition of higher heat value relative to the leannatural gas.

FIGS. 2 a and 2 b are simplified block flow diagrams illustratingembodiments of the present invention, wherein a lean natural gas isblended with a synthetic hydrocarbon component in the vapor phase andthen condensed in a natural gas liquefaction process to produce ablended liquid product. The synthetic hydrocarbons can comprise a“synthetic LPG” derived from a Fischer-Tropsch hydrocarbon synthesisprocess as illustrated in FIG. 2 a, which may also produce liquidproducts, such as naphtha, diesel, and lube blending stocks.Alternatively, as illustrated by FIG. 2 b, the synthetic hydrocarbonscan comprise olefins and/or paraffins derived from methanol ordimethylether via a methanol to olefins process as describedhereinafter. The blended liquid product may then be convenientlytransported to a distant market, and later re-gasified at a site remotefrom the location where the blended liquid product is produced orliquefied to provide a fuel composition with greater heat value relativeto the lean natural gas.

FIGS. 3 a and 3 b are simplified block flow diagrams illustrating otherembodiments of the present invention, wherein LNG produced from a leannatural gas and a synthetic hydrocarbon component are re-gasified andmixed in the vapor phase to produce a fuel blend according to theinvention. The synthetic hydrocarbons can similarly comprise a“synthetic LPG” derived from a Fischer-Tropsch hydrocarbon synthesisprocess as illustrated in FIG. 3 a. Alternatively, as illustrated byFIG. 3 b, the synthetic hydrocarbons can comprise olefins and/orparaffins derived from methanol or dimethylether via a methanol toolefins process. The LNG and synthetic hydrocarbon employed may bemanufactured at a location where the raw natural gas used to make theLNG is produced from a subterranean reservoir. The LNG and synthetichydrocarbon can then be conveniently transported to a distant market,and later re-gasified and mixed to provide a fuel blend composition withgreater heat value relative to the lean natural gas.

DETAILED DESCRIPTION OF THE INVENTION

As mentioned above, the fuel compositions of the invention are comprisedof a natural gas component and a synthetic hydrocarbon component, bothas described hereinafter.

The natural gas feed employed for preparation of the natural gascomponent may be any natural or synthetic light hydrocarbon-containinggas, such as produced from natural gas, coal, shale oil, residua orcombinations thereof, which can be used as a fuel gas. Advantageously itis a lean virgin natural gas with a relatively low heating value, suchas less than 1000 BTU/scf. As used herein, the term “virgin” inreference to hydrocarbons means hydrocarbons that have not been obtainedby hydrocarbon synthesis methods, such as an MTO process orFischer-Tropsch synthesis as described hereinafter. A “synthetichydrocarbon” is a hydrocarbon obtained by chemical conversion of anothercarbon-containing feedstock, such as by a Fischer-Tropsch hydrocarbonsynthesis as described hereinafter, or alternatively olefins and/orparaffins derived from methanol and/or dimethylether feed via a methanolto olefins synthesis as described hereinafter. In embodiments, thesynthetic hydrocarbon component comprises a blend of C₂ to C₅ syntheticolefins, paraffins, or mixtures thereof in any combination.

The natural gas feed mentioned above may also be conveniently used toprepare LNG and/or a synthetic hydrocarbon component for use inpreparing the fuel compositions according to the invention, as describedhereinbelow.

The natural gas feed contemplated for use herein generally comprises atleast 50 mole percent methane, preferably at least 75 mole percentmethane, and more preferably at least 90 mole percent methane. Thebalance of the natural gas feed, as mentioned briefly hereinabove, cangenerally comprise other combustible hydrocarbons such as, but notlimited to, lesser amounts of ethane, propane, butane, pentane, andother higher boiling hydrocarbons, and non-combustible components suchas carbon dioxide, hydrogen sulfide, helium and nitrogen.

The presence of an excessive amount of heavier virgin hydrocarbons suchas ethane, propane, butane, pentane, and hydrocarbons boiling at aboiling point above pentane, which may be present in some natural gasfeeds can optionally be reduced through gas-liquid separation steps,particularly in the event such hydrocarbons have greater value for useoutside the production of a fuel composition, LNG or synthetichydrocarbons as mentioned below. Hydrocarbons boiling at a temperatureabove the boiling point of pentane or hexane are generally directed tocrude oil. Hydrocarbon boiling substantially at a temperature above theboiling point of ethane and below the boiling point of pentane or hexaneare typically removed from the methane feed to an LNG process, and aresometimes considered to be natural gas liquids or “NGLs”. Excessiveamounts of these heavier hydrocarbons are also typically removed fromnatural gas produced from a formation in preparation of a natural gasfuel.

The natural gas feed processed in accordance with the present inventionis preferably a lean natural gas such that it may be directed to themanufacture of the fuel compositions, LNG or synthetic hydrocarbonswithout requiring additional processing steps for removal of NGLs.

For most markets, it is also desirable to minimize the presence ofnon-combustibles and contaminants in the LNG or fuel gas, such as carbondioxide, helium and nitrogen and hydrogen sulfide. Depending on thequality of a given natural gas reservoir (which may contain as much as50% to 70% carbon dioxide), the natural gas may be pre-treated at anatural gas plant for pre-removal of the above components or may beconveyed directly to an LNG or related plant for pre-processing prior tomanufacture of fuel products. Typically, as mentioned above, there aremany natural gas reservoirs that contain significant amounts ofnon-combustible CO₂ gas therein. At present, commercial scale LNG plantsuse processes which generally—require nearly complete removal of acidgases, including CO₂, from the feed gas to the LNG process. In the past,the CO₂ extracted from the feed gas has been simply vented to theatmosphere. However, current concerns over global warming,internationally driven initiatives to reduce greenhouse emissions, andother environmental factors make venting of such CO₂ undesirable. Asmentioned below, the CO₂ removed from a natural gas feed can berecovered and used to make methanol and synthetic hydrocarbons, such assynthetic olefins and/or paraffins, for use in accordance with thepresent invention.

Pretreatment steps suitable for use with the present invention generallybegin with steps commonly identified and known in connection with LNGproduction or hydrocarbon synthesis, including, but not limited to,removal of acid gases (such as H₂S and CO₂), mercaptans, mercury andmoisture from the natural gas feed stream. Acid gases and mercaptans arecommonly removed via a sorption process employing an aqueousamine-containing solution or other types of known physical or chemicalsolvents. This step is generally performed upstream of most of thenatural gas processing steps. A substantial portion of the water isgenerally removed as a liquid through two-phase gas-liquid separationprior to or after low level cooling, followed by molecular sieveprocessing for removal of trace amounts of water. Mercury is removedthrough use of mercury sorbent beds. Residual amounts of water and acidgases are most commonly removed through the use of particularly selectedsorbent beds such as regenerable molecular sieves. Such particularlyselected sorbent beds are also generally positioned upstream of most ofthe natural gas processing steps. Preferably, the pretreatment of thenatural gas feed results in a CO₂ content of less than 0.1 mole percent,and more preferably less than 0.01 mole percent, based on the totalnatural gas feed.

In accordance with some embodiments of the invention, it is desirable toprepare a CO₂ rich stream for use in the manufacture of methanol andlight synthetic hydrocarbons, wherein the CO₂ rich stream has minimalamounts of contaminants, such as H₂S, mercaptans, and othersulfur-containing compounds.

As known in the art, an inhibited amine solution can be used toselectively remove the CO₂ in the natural gas stream, but not H₂S. TheH₂S can then be removed in a subsequent step. Also, it is desirable toemploy a guard bed (such as a ZnO guard bed) for removal of anyremaining, residual sulfur-containing compounds that may be present inthe CO₂ rich stream prior to feeding the stream to points within ahydrocarbon synthesis process, such as upstream of a pre-reformingreactor or reforming reactor. Such reactors typically employ nickelcatalysts which can be susceptible to poisoning by sulfur-containingcompounds, such as H₂S.

In some embodiments, the natural gas component employed in the presentinvention may be a stream that is obtained from the natural gas feedafter pre-treatment as previously mentioned, or in other embodiments itis a stream arising from an LNG process for the preparation of LNG; or astream obtained by regasification of an LNG product.

In general, where the natural gas component is derived from LNG, the LNGmay be prepared according to any known LNG process as previouslydescribed. For example, processes for preparation of LNG generally aredisclosed in U.S. Pat. Nos. 4,445,917; 5,537,827; 6,023,942; 6,041,619;6,062,041; 6,248,794, and UK Patent Application GB 2,357,140 A, theteachings of which are incorporated herein by reference in theirentirety. Another LNG process which is integrated with other processesto produce liquid products from natural gas is also disclosed in U.S.Pat. No. 6,743,829, and further U.S. patent application Ser. No.10/805,943, filed Mar. 22, 2004 discloses an integrated process whereinCO₂ present in natural gas feedstreams for preparation of LNG isrecovered for use in making methanol and methanol derivatives, such asdimethyl ether. The teachings of the foregoing patent and patentapplication are incorporated herein by reference in their entirety.

The synthetic hydrocarbon component can be prepared by any known method,and particularly an indirect synthesis process, wherein the natural gasfeed stream is passed to a synthesis gas plant for conversion of thefeed stream to synthesis gas, and the synthesis gas is thereafterconverted to oxygenates, such as methanol, which may then be convertedto hydrocarbons, such as olefins or paraffins. Alternatively, thesynthesis gas may be converted directly to such hydrocarbons viaFischer-Tropsch synthesis. If not already removed as previouslydescribed, impurities such as sulfur compounds, nitrogen compounds,particulate matter, and condensables are removed so as to ultimatelyprovide a synthesis gas stream reduced in contaminants and containing amolar ratio of hydrogen to carbon oxide (carbon monoxide plus carbondioxide). A carbon oxide, as used herein, refers to carbon dioxideand/or carbon monoxide. Synthesis gas refers to a combination ofhydrogen and carbon oxides produced in a synthesis gas plant from alight hydrocarbon gas as previously described.

The reaction of synthesis gas to oxygenates such as methanol isexothermic, can be conducted in the gas phase or liquid phase, and isfavored by low temperature and high pressure over a heterogeneouscatalyst. The methanol synthesis reactions employed on an industrialscale can be illustrated by the following equations:CO+2H₂⇄CH₃OHorCO₂₊₃H₂⇄CH₃OH+H₂OThe catalyst formulations employed typically include copper oxide(60-70%), zinc oxide (20-30%) and alumina (5-15%). Chapter 3 of MethanolProduction and Use, edited by Wu-Hsun Cheng and Harold H. Kung, MarcelDekker, Inc., New York, 1994, pages 51-73, provides a summary ofconventional methanol production technology with respect to catalyst,reactors, typical yields operating conditions. The above reference ishereby incorporated by reference.

Methanol is generally produced in what is known as a “synthesis loop”which incorporates the generation of the synthesis gas. Althoughsynthesis gas may also be produced from coal gasification and partialoxidation, the primary route employed currently by industry is via thesteam reforming of natural gas. The steam reformer is essentially alarge process furnace in which catalyst-filled tubes are heatedexternally by direct firing to provide the necessary heat for thefollowing reaction, known as the water-gas shift reaction to take place:C_(n)H_(2n+2) +nH₂O⇄nCO+(2n+1)H₂wherein n is the number of carbon atoms per molecule of hydrocarbon.

Generally, the production of oxygenates, primarily methanol, takes placeas a combination of process steps. The process steps can include:synthesis gas preparation, methanol synthesis, and if needed, methanoldistillation.

In the synthesis gas preparation step, the hydrocarbon gas feedstock ispurified to remove sulfur and other potential catalyst poisons prior tobeing converted into synthesis gas. The conversion to synthesis gasgenerally takes place at high temperatures over a nickel-containingcatalyst to produce a synthesis gas containing a combination ofhydrogen, carbon monoxide, and carbon dioxide. Typically, the pressureat which synthesis gas is produced ranges from about 20 to about 75 barand the temperature at which the synthesis gas exits the reformer rangesfrom about 700° C. to 1100° C. The synthesis gas contains astoichiometric molar ratio of hydrogen to carbon oxide, generallyexpressed as follows:S_(n)=[H₂—CO₂]/[CO+CO₂]which is generally from 2 to 3 and more typically from about 2.0 to 2.3.The synthesis gas is subsequently compressed to a methanol synthesispressure as described below. In the methanol synthesis step, thecompressed synthesis gas is converted to methanol, water, and minoramounts of by-products.

The synthesis gas preparation may take place in a single-step whereinall of the energy consuming reforming reactions are accomplished in asingle tubular steam reformer. The single-step reformer results in aproduction of surplus hydrogen and a substantial heat surplus. Inanother preferred alternative, the synthesis gas preparation may takeplace in a two-step reforming process wherein the primary reforming in atubular steam reformer is combined with an oxygen-fired secondaryreforming step which produces a synthesis gas with a deficiency inhydrogen. With this combination it is possible to adjust the synthesisgas composition to the most suitable composition for methanol synthesis.As an alternative, autothermal reforming—wherein a stand-alone,oxygen-fired reformer produces synthesis gas having a hydrogendeficiency followed by the downstream removal of carbon dioxide torestore the desired ratio of hydrogen to carbon oxide—can result in asimplified process scheme with lower capital cost.

As disclosed in U.S. Pat. No. 3,326,956, low-pressure methanol synthesisis based on a copper oxide-zinc oxide-alumina catalyst that typicallyoperates at a nominal pressure of 5-10 MPa (50-100 bar) and temperaturesranging from about 150° C. (302° F.) to about 450° C. (842° F.) over avariety of catalysts, including CuO/ZnO/Al₂O₃, CuO/ZnO/Cr₂O₃, ZnO/Cr₂O₃,Fe, Co, Ni, Ru, Os, Pt, and Pd. Catalysts based on ZnO for theproduction of methanol and dimethyl ether are preferred. Thelow-pressure, copper-based methanol synthesis catalyst is commerciallyavailable from suppliers such as BASF, ICI Ltd., and Haldor-Topsoe.Methanol yields from copper-based catalysts are generally over 99.5% ofthe combined CO+CO₂ present as methanol in the crude product stream.Water is a by-product of the conversion of the synthesis gas tooxygenates. Methanol and other oxygenates produced in the above mannerare herein further referred to as an oxygenate feedstock.

U.S. patent application Ser. No. 10/805,943 filed on Mar. 22, 2004,previously incorporated herein by reference, discloses a process forintegration of LNG processes with other processes to prepare liquidproducts from natural gas, such as a methanol production processcomprising conversion of the natural gas to synthesis gas (H₂ and CO)and then conversion of the synthesis gas to methanol. In the disclosedprocess, the non-combustible CO₂ gas separated from the raw natural gasprior to being fed to the LNG process is recovered and subsequentlyutilized in the production of methanol. The CO₂ can be converted tomethanol by any known synthesis method, such as those previouslydescribed. As a result, CO₂ which would otherwise have been vented toatmosphere can be advantageously converted to higher value products,such as methanol and dimethyl ether.

An embodiment of the invention derived from the process disclosed inU.S. Ser. No. 10/805,943 is illustrated in FIG. 1. Separation of the CO₂from the natural gas as produced from a reservoir is not shown on FIG. 1for convenience, but may be done by any of a number of pre-treatmentsteps known to the art as mentioned hereinabove.

As shown in FIG. 1, all or a portion of the CO₂ recovered from suchpre-treatment steps may be conveyed by lines 8 and 10 and then combinedwith a natural gas stream in line 4 to produce a blended feed streamwhich is conveyed by line 12 to a heater 20. After being heated inheater 20, the blended feed stream is then conveyed by line 25 to aguard bed vessel 30 wherein any residual amount of sulfur-containingcontaminants present in the blended feed stream may be removed bycontact with an adsorbent bed, typically of zinc oxide. Alternatively,the CO₂ stream conveyed by lines 8 and 10 and natural gas streamconveyed by line 4 could be treated individually in such guard beds.

After treatment in the guard bed 30, steam is added to the blended feedstream via line 38. The blended feed stream is then conveyed by line 35to heater 40 wherein the temperature thereof is further adjusted to from300° C. (572° F.) to 450° C. (842° F.) prior to introducing the blendedfeed stream via line 45 to pre-reformer reactor vessel 50. Pre-reformerreactor vessel 50 typically contains a nickel-based reforming catalyst,but may be any of a number of reforming catalysts as known in the art,and is designed to convert higher hydrocarbons which may be present inthe blended feed stream and produce a predominately methane-containingfeed stream. Effluent from pre-reformer reactor vessel 50 is conveyed byline 55 to a heater 70 which heats the effluent to a temperaturesuitable for steam reforming of the methane-containing stream intosynthesis gas, typically a temperature of from 400° C. (752° F.) to 500°C. (932° F.). In the event that the CO₂ feed in line 8 is substantiallyfree of sulfur-containing compounds, such as less than 1 ppm, it ispossible to add CO₂ to the process at the location identified as 60 onFIG. 1, by conveying all or part of the CO₂ to this location via line58.

After being heated to a temperature suitable for steam reformation, themethane-containing stream is conveyed by line 75 to steam reformervessel 80. Steam reformer vessel 80 typically contains anickel-containing steam reforming catalyst, but may be any of thoseknown in the art, which converts the methane-containing stream into onerich in synthesis gas, i.e., hydrogen gas and carbon oxides. Thesynthesis gas stream exiting steam reformer vessel 80 is conveyed byline 85 to a heat exchanger 90 where excess heat therein is recoveredfor other uses, such as in heaters 20 and 40. The synthesis gas streamis then conveyed by line 95 to a cooler 100 wherein the temperature isfurther reduced. The so-cooled synthesis gas stream is conveyed by line105 to separator 110 wherein condensed water may be removed from theprocess by line 115. The synthesis gas stream is thereafter conveyed byline 120 to synthesis gas compressor 130 which compresses the stream toa pressure suitable for methanol production, such as 35 to 150 bar. Thecompressed synthesis gas stream is then conveyed by lines 135 and 140 toheat exchanger 150 wherein the temperature is adjusted to that suitablefor methanol production, such as from 200° C. (392° F.) to 300° C. (572°F.).

After adjustment of temperature, the synthesis gas stream is conveyed byline 155 to methanol synthesis reactor 160. Methanol synthesis reactor160 generally utilizes a catalyst, such as a copper-zinc-aluminacatalyst as mentioned above, but may be any of those known in the art.Effluent from the methanol synthesis reactor 160 comprised primarily ofmethanol, water, and unreacted synthesis gas is conveyed by line 165 toheat exchan ger 150 wherein excess heat is recovered therefrom, andthereafter the effluent is conveyed by line 170 to cooler 175.Thereafter, the effluent is conveyed by line 178 to separator 180wherein a crude methanol product is recovered through line 210 and agaseous stream exits by line 185. A purge gas stream, which may be usedas fuel gas, is taken off via line 190 and the remainder of the gaseousstream comprised of unreacted synthesis gas is directed by line 195 torecycle compressor 200 which recompresses the gaseous stream to thatsuitable for methanol synthesis as previously described. The compressedgaseous stream is directed by line 205 to line 135 and mixed with freshsynthesis gas.

The resulting crude methanol product from line 210 can then be purifiedby methods as known in the art, such as distillation, and then readilyconverted to olefins by known methods.

Molecular sieves such as the microporous crystalline zeolite andnon-zeolitic catalysts, particularly silicoaluminophosphates (SAPO), areknown to promote the conversion of oxygenates, such as methanol, toolefins and other hydrocarbon mixtures. Numerous patents describe thistype of process which also employ various types of catalysts, see, e.g.,U.S. Pat. Nos. 3,928,483; 4,025,575; 4,252,479; 4,496,786; 4,547,616;4,677,243; 4,843,183; 4,499,314; 4,447,669; 5,095,163; 5,126,308;4,973,792; and 4,861,938, the teachings of which are incorporated hereinby reference. Such processes are referred to in the art as “MTO”(methanol-to-olefin) type processes, which typically result inconversion of light oxygenates, such as methanol, to light olefins.

The above-described oxygenate conversion process may also be generallyconducted in the presence of one or more diluents which may be presentin the oxygenate feed in an amount between about 1 and about 99 molarpercent, based on the total number of moles of all feed and diluentcomponents fed to the reaction zone (or catalyst). Diluents include—butare not limited to—helium, argon, nitrogen, carbon monoxide, carbondioxide, hydrogen, water, paraffins, hydrocarbons (such as methane andthe like), aromatic compounds, or mixtures thereof. U.S. Pat. Nos.4,861,938 and 4,677,242 particularly emphasize the use of a diluentcombined with the feed to the reaction zone to maintain sufficientcatalyst selectivity toward the production of light olefin products,particularly ethylene. The foregoing U.S. Patents are incorporatedherein by reference in their entirety.

In FIG. 1, all or a portion of the crude methanol product can beconveyed via line 210 to olefin synthesis reactor 220, wherein the crudemethanol (or oxygenate feedstock) is converted to light olefins asdescribed above. A portion of the crude methanol may be taken off vialine 215 and purified by distillation or other unit operation (notshown). The olefin-containing reaction product from olefin synthesisreactor 220 exits via line 225 and is conveyed to separator 230 whereinthe olefins may be separated as desired, for example, into respectiveolefin product streams 234, 236, and 238. All or any portion of therespective olefin product streams may then be used as the synthetichydrocarbon component in accordance with the present invention. Aby-product (water) stream exits separator 230 via line 232.

If desired, the light olefins obtained as described above may behydrogenated by well-known methods and thereby converted into lightparaffinic hydrocarbons. Such methods and catalysts therefor aredescribed in U.S. Pat. No. 4,075,251, the teachings of which areincorporated herein by reference. Catalysts include various transitionmetal catalysts as mentioned in the foregoing U.S. Patent, and arecommercially available. In general, olefins may be converted toparaffins by contact with the foregoing catalysts and hydrogen orhydrogen-containing gases at temperatures ranging from about 0° F.(−17.8° C.) to about 1000° F. (537.8° C.), more typically temperaturesranging from about 100° F. (37.8° C.) to about 500° F. (260° C.). Thereactions can be conducted at lower than atmospheric pressures orgreater than atmospheric pressures, but generally pressures ranging fromas low as about 1 atmosphere (1 bar) to about 500 atmospheres (506.6bar), and specifically from about 1 atmosphere (1 bar) to about 50atmospheres (50.7 bar) are suitable. The catalysts and feedstock can becontacted as slurries or fixed beds, movable beds and fluidized beds, inliquid phase or vapor phase, in batch, continuous or staged operations.

In addition to oxygenates, the natural gas feed can also be convertedinto synthetic hydrocarbons, such as paraffins and olefins, viawell-known Fischer-Tropsch technology as illustrated generally by U.S.Pat. Nos. 6,248,794; 6,774,148 and 6,743,962, the teachings of which areincorporated by reference herein in their entirety.

Fischer-Tropsch synthesis in general exothermically reacts synthesisgas, i.e., hydrogen and carbon monoxide, over either an iron or cobaltbased catalyst to produce a range of synthetic hydrocarbon products. Thespecific hydrocarbon product distribution depends strongly on both thecatalyst and the reactor temperature. Generally, the higher the reactortemperature, the shorter the average hydrocarbon product chain length.Reactor temperatures are generally in excess of 350° F. (176.7° C.),generally from about 350° F. (176.7° C.) to about 650° F. (343.3° C.),and more typically from about 400° F. (204.4° C.) to about 500° F. (260°C.). The reaction pressure is generally maintained at between 200 psig(13.8 bar) and 600 psig (41.4 bar), and is typically from 300 psig (20.7bar) and 500 psig (34.5 bar). The Fischer-Tropsch reaction can beconducted in any of several known reaction devices such as, but notlimited to, a slurry reactor, an ebullated bed reactor, a fluidized bedreactor, a circulating fluidized bed reactor, and a multi-tubular fixedbed reactor.

The Fischer-Tropsch reaction can generate significant amounts of lightsynthetic hydrocarbons, either paraffins or olefins, which are usuallynot as desirable in and of themselves, as such Fischer-Tropsch processesare typically directed toward making higher molecular weight materials,i.e., distillate fuels. However, such light synthetic hydrocarbons canbe used as a synthetic hydrocarbon component (“synthetic LPG”) in makingthe fuel compositions according to the present invention.

While the foregoing has been described somewhat in detail, it should beunderstood that the synthetic hydrocarbon component can be derived fromany other source or method known in the art. Direct methods forsynthesis of hydrocarbons from methane are known and may also beutilized. The natural gas component mixed therewith may be derived fromLNG or simply comprise natural gas produced from a subterraneanreservoir or formation with or without pretreatment to removecontaminants as described herein.

In accordance with the foregoing embodiment of the present invention,during production of LNG in a natural gas liquefaction process aspreviously mentioned, the synthetic hydrocarbon component may be blendedinto the feed stream to be liquefied in the LNG process at a pointbefore the methane gas stream is cooled to about the freezing point ofthe highest boiling hydrocarbon present in the synthetic hydrocarboncomponent. The synthetic hydrocarbon should be blended into the feedstream above this temperature so that a separate, solid phase ofsynthetic hydrocarbon is not formed in the natural gas feed stream.Also, in this embodiment, it is important to maintain the synthetichydrocarbon content within the feed stream being liquefied below asaturation point so that the synthetic hydrocarbon does not solidify andcreate a separate solid phase. Generally, this concentration is about 25mole % based on total amount of blended liquid product.

FIGS. 2 a and 2 b illustrate in simple terms the method of blending ofsynthetic hydrocarbon into natural gas during production of a LNGproduct in a natural gas liquefaction process according to theembodiment just mentioned.

Mixing of the synthetic hydrocarbon and LNG product in the liquid phaseafter production of the LNG is not as desirable, due to the limitedsolubility of the synthetic hydrocarbon therein, and also greatertendency of the synthetic hydrocarbon to form an undesirable solidphase.

It is generally more favorable and convenient to mix the synthetichydrocarbon into a natural gas component in the vapor phase. In thiscase, the natural gas component may be a natural gas obtained byre-gasification of an LNG product, or it may be a natural gas obtainedfrom another source, such as by production from a subterraneanreservoir, with or without the one or more of the pre-treatment stepspreviously mentioned. If the synthetic hydrocarbon is to be blended withthe LNG after re-gasification, then a larger amount of such contaminantscan be tolerated so long as the contaminants do not inhibit the intendeduse of such blend, as in for example, use as a fuel composition. Also,the synthetic hydrocarbon has physical properties more like LPG, andthus it may be stored as a liquid under pressures similar to those usedin connection with storage of LPG. Just prior to use, the synthetichydrocarbon may be re-gasified, such as by reduction of pressure, andthen mixed with the natural gas component. Alternatively, the synthetichydrocarbon may be directly injected and mixed with the re-gasified LNG.

In accordance with the foregoing embodiment of the invention whereinsynthetic hydrocarbon is mixed with a natural gas component in the gasphase, the blending of the synthetic hydrocarbon can be generallyaccomplished without significant attention to keeping the synthetichydrocarbon concentration relatively low. As such, mixtures having arelatively larger amount of synthetic hydrocarbon mixed with the naturalgas component can be prepared by this embodiment. Typically, incommercial practice and as a preferred embodiment of the invention, itwould only necessary to blend in enough synthetic hydrocarbon so thatthe ultimate, blended natural gas product has a higher heating valuewhich meets a consumer's specification, as the synthetic hydrocarbon isa higher value component relative to the natural gas. Typical desiredheating values are mentioned herein.

More importantly, the upper limit for the amount of synthetichydrocarbon added will be that which allows the resulting fuel blend tobe maintained below the hydrocarbon dew point for the pressure andtemperature at which the fuel blend is to be stored or conveyed,typically those conditions being specified for the pipeline in which thefuel blend is to be conveyed to market or the ultimate user thereof. Assuch, the customer specification can usually be attained by preferablyblending in a minor amount of synthetic hydrocarbon, such as less than25 mol % based on the total fuel composition, generally less than 20 mol%, and beneficially from 15 mol % to 10 mol % due to theseconsiderations. In this embodiment, the synthetic hydrocarbon may beconveniently added at any temperature up to the applicable dew point ofthe natural gas component employed so that no liquids condense from thegas phase.

Mixing of the synthetic hydrocarbon and natural gas component in the gasphase according to this embodiment of the invention may be conducted inany process vessel, such as a pipe or tank.

FIGS. 3 a and 3 b illustrate in simple terms the blending of synthetichydrocarbon into a natural gas component derived from LNG in the vaporphase after re-gasification of the LNG at, for example, are-gasification facility near a market site for such gas product.Re-gasification methods for LNG are generally known in the art.Preferably, the synthetic hydrocarbon employed will be stored in aliquid state, which is also more convenient and economical for transportof the synthetic hydrocarbon composition to a market site, and then thesynthetic hydrocarbon is re-gasified prior to or during blending withthe re-gasified LNG. Re-gasification methods for LNG can also be used tore-gasify the synthetic hydrocarbon. Further, such re-gasificationmethods can also be used to re-gasify a synthetic hydrocarbon/LNG blendwhich is in a liquid state according to the aspect of the inventionpreviously mentioned.

A particular blended synthetic hydrocarbon/LNG liquid product, inaccordance with the present invention, generally comprises:

-   -   less than 2 mole percent nitrogen and preferably less than 1        mole percent nitrogen;    -   less than 1 mole percent and preferably less than 0.5 mole        percent helium;    -   less than 3 mole percent and preferably less than 1.5 mole        percent of the total of nitrogen and helium; and    -   less than 25 mole percent of synthetic hydrocarbon within the        blended liquid product.

Where the synthetic hydrocarbon is blended into a regasified LNGproduct, according to one aspect of the invention, the resulting fuelblend preferably comprises:

-   -   less than 0.3 mole percent nitrogen and preferably less than 0.2        mole percent nitrogen;    -   less than 0.2 mole percent and preferably less than 0.1 mole        percent helium;    -   less than 0.5 mole percent and preferably less than 0.2 mole        percent of the total of nitrogen and helium; and    -   less than 25 mol % synthetic hydrocarbon, based on the total        fuel blend, typically less than 20 mol %, and beneficially from        10 to 15 mol % synthetic hydrocarbon based on the total fuel        blend.

A typical gross heating value for the fuel composition produced inaccordance with the present invention generally ranges from about 1000Btu/scf to about 1200 Btu/scf, and more typically from about 1030Btu/scf to about 1170 Btu/scf, and particularly from about 1050 BTU/scfto about 1150 BTU/scf.

As can be seen, the present invention relates to alternative productsand methods which may be used to provide more economical and convenientfuel compositions having improved heating values.

Other embodiments and benefits of the invention will be apparent tothose skilled in the art from a consideration of this specification orfrom practice of the invention disclosed herein. It is intended thatthis specification be considered as exemplary only with the true scopeand spirit of the invention being indicated by the following claims.

1. A composition comprising a virgin natural gas component and asynthetic hydrocarbon component comprised of light hydrocarbons.
 2. Thecomposition of claim 1 wherein the virgin natural gas component is alean natural gas.
 3. The composition of claim 2 wherein the lean naturalgas employed comprises less than about 3 mol % of C₂ to C₅ virgin lighthydrocarbons, with the balance of the lean natural gas being essentiallymethane, based on the composition of the lean natural gas.
 4. Thecomposition of claim 1 wherein the synthetic hydrocarbon component ispresent in an amount of less than 25 mol % based on the totalcomposition.
 5. The composition of claim 1 wherein the natural gascomponent is derived from a regasified LNG product produced in an LNGprocess.
 6. The composition of claim 1 having a heating value of fromabout 1000 BTU/scf to about 1200 BTU/scf.
 7. The composition of claim 1wherein the synthetic hydrocarbon component comprises C₂ to C₅hydrocarbons selected from paraffins, olefins, and mixtures thereof. 8.The composition of claim 7 wherein the synthetic hydrocarbon componentis derived from a Fischer-Tropsch process.
 9. The composition of claim 7wherein the synthetic hydrocarbon component is derived from an MTOprocess.
 10. A method for preparing a fuel blend comprising mixing avirgin natural gas component and a synthetic hydrocarbon componentcomprised of light synthetic hydrocarbons.
 11. The method of claim 10wherein the virgin natural gas component is derived from a regasifiedLNG product prepared in a LNG process.
 12. The method of claim 11further comprising: pre-treating a natural gas stream comprising acidgases, water and other contaminants therein to remove at least a portionof the contaminants therefrom and provide a natural gas feed; coolingthe natural gas feed in the LNG process to liquefy at least a portion ofthe natural gas component and thereby produce a LNG product; andre-gasifying the LNG product to obtain the natural gas component. 13.The method of claim 12 further comprising: providing the synthetichydrocarbon component; and mixing the synthetic hydrocarbon componentwith the virgin natural gas component to obtain the fuel blend.
 14. Themethod of claim 13 wherein mixing of the virgin natural gas componentand the synthetic hydrocarbon component occurs at a site remote from thelocation where the virgin natural gas component originates.
 15. Themethod of claim 11 wherein the synthetic hydrocarbon component isblended in an amount such that the concentration of the synthetichydrocarbon component in the fuel blend is less than 25 mol % based onthe total fuel blend.
 16. The method of claim 11 wherein the fuel blendhas a heating value of from about 1000 BTU/scf to about 1200 BTU/scf.17. The method of claim 10 further comprising: pre-treating a naturalgas stream comprising acid gases, water and other contaminants thereinto remove at least a portion of the contaminants therefrom and provide anatural gas feed for a LNG process; mixing the synthetic hydrocarboncomponent into the natural gas feed within a LNG process at atemperature and in an amount such that the synthetic hydrocarbon doesnot solidify and form a separate solid phase during liquefaction of thenatural gas feed in the LNG process; and cooling the resulting naturalgas and synthetic hydrocarbon mixture within the LNG process to atemperature of from about −240° F. (−151° C.) to about −260° F. (−162°C.) or less so as to liquefy at least a portion of the mixture andthereby produce a blended liquid product at substantially atmosphericpressure; and re-gasifying the blended liquid product to produce thefuel blend.
 18. The method of claim 17 wherein the fuel blend comprisesthe synthetic hydrocarbon component in an amount of 25 mole % or lessbased on the total fuel blend.
 19. A method for preparing a fuel blendcomprising virgin natural gas and synthetic hydrocarbons, the methodcomprising: pre-treating a natural gas stream comprising acid gases,water and other contaminants therein to remove at least a portion of thecontaminants therefrom and provide a natural gas feed; cooling thenatural gas feed in a LNG process to liquefy at least a portion of thenatural gas feed and thereby produce a LNG product; providing asynthetic hydrocarbon component; re-gasifying the LNG product to obtaina virgin natural gas component; and mixing the synthetic hydrocarboncomponent with the virgin natural gas component to obtain the fuelblend.